In the production of underground petroleum products (oil and gas), it is important to determine the fractions of flow through a wellbore that are attributed to different components, that is, oil, water and gas. For example, it is known that water production often increases as oil reserves are depleted, or in response to a water injection program. When the degree of water present in the production flow becomes excessive, production logging surveys are used to determine the locations and rates of water entry into the flow regime. These surveys include both measurements of fluid velocities and attempts at determining the average fractional percentages of the well fluids at various survey depths.
Various methods have been devised to calculate the fractional percentages, or “holdups,” of a phase component in the fluid flow. At a particular depth, the holdup of a specified phase (gas, oil, or water) is defined as the fraction of the cross sectional area of the casing or tubing that is occupied by that phase. The traditional holdup logging devices are the radioactive fluid-density (gamma-gamma attenuation) and the water-holdup (capacitance, or dielectric) tools. In addition, it is known to use a gradiomanometer, a device which measures pressure gradient over a given height, which gradient may be considered as being a function solely of the difference in level between the two measurement points and of the apparent density of the fluid. Given the respective densities of the various phases, it is then possible to calculate the various proportions thereof. Another approach consists in taking measurements by means of local sensors that produce signals having different levels depending on which phase is in contact with the sensor. U.S. Pat. No. 3,792,347 (Hawley) thus proposes an electrical type measurement by measuring resistivity. U.S. Pat. No. 6,023,340 (Wu et al.) proposes a fiber optic type measurement by measuring optical reflectance.
Recent devices derive the wellbore cross-sectional averaged volumetric flow rate and holdup from a number of oriented local measurements made within the wellbore. The principal devices for measuring flow rates employ propellers or turbines which are assumed to measure the average volumetric flow rate of the entire fluid mixture. In the process of the flow rate determination, logging measurements are used to calculate the holdup occupied by each of the flowing fluids. The spatial distribution of the fluids in the wellbore can also be used to aid in this determination. Sensors (for example local probes and mini-spinners) located on various known points of the cross section of the well are used as stated in the document WO 01/11190. Local probe measurements provide a means to evaluate this spatial distribution and holdup. A method for calculating the relative volumetric flow rates of at least one of the phases of a multiphase effluent flowing in a well is known as stated in US Patent pplication 20060041382. However, the dynamic nature of downhole flow leads to variations and local, temporary anomalies in the flow structure so that they are not representative of the overall flow behavior.
Therefore, the interpretation of these data, collected at each local spinner and probe in order to calculate relative volumetric flow rates at all depths, is thus becoming a very important procedure in order to estimate the behavior of each fluid constituting the well effluent.